Subsea production of oil and gas is projected to increase significantly in the next 5-10 years. However, producing oil and gas from floating production platforms (FPSO) presents many challenges which increase as the water depth increases. The fluids produced from the wellheads on the seabed are typically transferred to the FPSO through flexible flowlines (also known as risers or pipelines). However, because the temperature of the fluid in the flowline can change as flow conditions change, waxes or hydrates can deposit on the inside of the flowlines. In particular, when production is stopped, the temperature of the fluid in the line will decrease as a result of heat loss to the surrounding, cooler sea water. The fluid condition can thus enter a state which triggers hydrate formation.
The conditions for deposit formation are typically anticipated through computer modeling of the flowline using expected environmental conditions, such as temperature and pressure, together with thermodynamic modeling of the fluids being transported. One industry accepted flow modeling package is OLGA from SPT Group. This modeling package is used during the design and operation phases of a flowline. It relies heavily on estimates of expected operating conditions and flowing fluid properties. These are not always well known and so unexpected deposition may occur.
It is not uncommon for deposition to go undetected until flow is completely blocked or is so restricted that oil and gas production is significantly effected. Pressure and flow measurements are sometimes used but these are usually only available at discrete locations which are often separated by large distances. As result, blockage or deposit location can only be determined to within a very long section of a flowline.
In addition, it is often difficult to determine the location of deposit formation as it will depend on changes in fluid and environmental conditions along the flowline. It is also found that hydrate deposits can move through the flowline and aggregate to form a blockage at a point away from where they were first formed. If deposition is allowed to continue, the cost associated with removing the blockage can be significant. Accordingly, the sooner deposition is detected the better.
Removal of hydrate deposits is typically performed by pumping large quantities of chemicals into sections of flowlines (“chemical injection”) or by sending a “pig” into the flow lines to scrape off or break up any deposits formed within the flowline. Both approaches require information about the location of the deposits to be removed in order to work effectively.